Tri-State Generation & Transmission Association 10-Q 7 May 21 2021 Q1 Quarterly report Financial data

Cover Page

Cover Page - shares shares in Thousands	3 Months Ended
	Mar. 31, 2021	May 07, 2021
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2021
Document Transition Report	false
Entity File Number	333-212006
Entity Registrant Name	TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.
Entity Incorporation, State or Country Code	CO
Entity Tax Identification Number	84-0464189
Entity Address, Address Line One	1100 West 116th Avenue
Entity Address, City or Town	Westminster,
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80234
City Area Code	303
Local Phone Number	452-6111
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		0
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q1
Entity Central Index Key	0001637880
Amendment Flag	false

Consolidated Statements of Fina

Consolidated Statements of Financial Position - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Electric plant
In service	$ 6,338,525	$ 6,254,652
Construction work in progress	85,386	89,447
Total electric plant	6,423,911	6,344,099
Less allowances for depreciation and amortization	(3,073,651)	(2,991,393)
Net electric plant	3,350,260	3,352,706
Other plant	457,837	456,924
Less allowances for depreciation, amortization and depletion	(145,304)	(133,012)
Net other plant	312,533	323,912
Total property, plant and equipment	3,662,793	3,676,618
Other assets and investments
Investments in other associations	164,248	162,975
Investments in and advances to coal mines	2,614	2,799
Restricted cash and investments	4,546	4,682
Other noncurrent assets	15,390	14,889
Total other assets and investments	186,798	185,345
Current assets
Cash and cash equivalents	109,483	127,187
Restricted cash and investments	274	205
Deposits and advances	37,604	32,012
Accounts receivable—Utility Members	88,369	96,637
Other accounts receivable	16,286	20,570
Electric plant held for sale	0	4,877
Coal inventory	53,211	55,762
Materials and supplies	81,567	82,119
Total current assets	386,794	419,369
Deferred charges
Regulatory assets	699,480	710,268
Prepayment—NRECA Retirement Security Plan	20,146	21,490
Other	46,638	33,646
Total deferred charges	766,264	765,404
Total assets	5,002,649	5,046,736
Capitalization
Patronage capital equity	969,029	978,519
Accumulated other comprehensive loss	(6,357)	(5,714)
Noncontrolling interest	113,807	114,851
Total equity	1,076,479	1,087,656
Long-term debt	3,147,423	3,200,181
Total capitalization	4,223,902	4,287,837
Current liabilities
Utility Member advances	18,128	16,592
Accounts payable	107,590	98,654
Accrued expenses	31,583	40,736
Current asset retirement obligations	11,080	11,044
Accrued interest	45,321	27,520
Accrued property taxes	27,503	32,794
Current maturities of long-term debt	94,592	87,587
Total current liabilities	335,797	314,927
Deferred credits and other liabilities
Regulatory liabilities	203,981	224,953
Deferred income tax liability	19,702	19,591
Asset retirement and environmental reclamation obligations	127,705	127,045
Other	72,401	54,600
Total deferred credits and other liabilities	423,789	426,189
Accumulated postretirement benefit and postemployment obligations	19,161	17,783
Total equity and liabilities	$ 5,002,649	$ 5,046,736

Consolidated Statements of Oper

Consolidated Statements of Operations (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Operating revenues
Other	$ 15,000	$ 10,890
Operating revenues	325,972	319,466
Operating expenses
Purchased power	87,017	71,015
Fuel	60,547	61,069
Production	40,901	43,188
Transmission	44,671	41,540
General and administrative	14,587	16,215
Depreciation, amortization and depletion	52,755	47,024
Coal mining	1,541	2,734
Other	2,551	7,683
Operating expenses	304,570	290,468
Operating margins	21,402	28,998
Other income
Interest	877	1,305
Capital credits from cooperatives	4,273	3,353
Other income (expense)	857	(250)
Total other income	6,007	4,408
Interest expense
Interest	36,115	38,867
Interest charged during construction	(974)	(1,961)
Interest expense, net of amounts capitalized	35,141	36,906
Income tax expense (benefit)	109	(209)
Net margins including noncontrolling interest	(7,841)	(3,291)
Net margin attributable to noncontrolling interest	(1,649)	(1,319)
Net margins attributable to the Association	(9,490)	(4,610)
Utility Member electric sales
Operating revenues
Operating revenues	272,798	292,763
Non-member electric sales
Operating revenues
Operating revenues	$ 38,174	$ 15,813

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Statement of Comprehensive Income [Abstract]
Net margins including noncontrolling interest	$ (7,841)	$ (3,291)
Other comprehensive loss:
Unrealized loss on securities available for sale	(34)	0
Amortization of actuarial loss on postretirement benefit obligation included in net margin	512	933
Unrecognized prior service cost	(1,121)	(7,373)
Other comprehensive loss	(643)	(6,440)
Comprehensive loss including noncontrolling interest	(8,484)	(9,731)
Net comprehensive income attributable to noncontrolling interest	(1,649)	(1,319)
Comprehensive loss attributable to the Association	$ (10,133)	$ (11,050)

Consolidated Statements of Equi

Consolidated Statements of Equity (unaudited) - USD ($) $ in Thousands	Total	Patronage capital	Accumulated other comprehensive income (loss)	Noncontrolling interest
Equity at beginning of period at Dec. 31, 2019		$ 1,031,063	$ (1,518)	$ 111,717
Change in Equity
Net margins attributable to the Association	$ (4,610)	(4,610)
Unrealized loss on securities available for sale	0		0
Amortization of prior service cost	933		933
Unrecognized prior service cost	(7,373)		(7,373)
Net comprehensive income attributable to noncontrolling interest	1,319			1,319
Equity distribution to noncontrolling interest				(1,268)
Equity at end of period at Mar. 31, 2020	1,130,263	1,026,453	(7,958)	111,768
Equity at beginning of period at Dec. 31, 2020	1,087,656	978,519	(5,714)	114,851
Change in Equity
Net margins attributable to the Association	(9,490)	(9,490)
Unrealized loss on securities available for sale	(34)		(34)
Amortization of prior service cost	512		512
Unrecognized prior service cost	(1,121)		(1,121)
Net comprehensive income attributable to noncontrolling interest	1,649			1,649
Equity distribution to noncontrolling interest				(2,693)
Equity at end of period at Mar. 31, 2021	$ 1,076,479	$ 969,029	$ (6,357)	$ 113,807

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Operating activities
Net margins including noncontrolling interest	$ (7,841)	$ (3,291)
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and depletion	52,755	47,024
Amortization of NRECA Retirement Security Plan prepayment	1,343	1,343
Amortization of debt issuance costs	627	602
Impairment loss	0	259,761
Deferred impairment loss and other closure costs	0	(268,163)
Recognition of deferred revenue	(20,834)	0
Deposits associated with generator interconnection requests	17,130	0
Capital credit allocations from cooperatives and income from coal mines over refund distributions	(1,159)	(693)
Changes in operating assets and liabilities:
Accounts receivable	10,224	14,230
Coal inventory	2,550	1,843
Materials and supplies	552	954
Accounts payable and accrued expenses	15,585	8,039
Accrued interest	17,800	17,321
Accrued property taxes	(5,291)	(2,063)
Other	(7,430)	(11,353)
Net cash provided by operating activities	76,011	65,554
Investing activities
Purchases of plant	(22,775)	(36,171)
Changes in deferred charges	(9,786)	(6,094)
Proceeds from other investments	72	68
Net cash used in investing activities	(32,489)	(42,197)
Financing activities
Changes in Member advances	1,536	(6,905)
Payments of long-term debt	(46,109)	(41,994)
Proceeds from issuance of long-term debt	0	200,000
Decrease in short-term borrowings, net	0	(87,600)
Retirement of patronage capital	(13,705)	(13,326)
Equity distribution to noncontrolling interest	(2,693)	(1,268)
Other	(322)	(195)
Net cash provided by (used in) financing activities	(61,293)	48,712
Net increase (decrease) in cash, cash equivalents and restricted cash and investments	(17,771)	72,069
Cash, cash equivalents and restricted cash and investments – beginning	132,074	113,768
Cash, cash equivalents and restricted cash and investments – ending	114,303	185,837
Supplemental cash flow information:
Cash paid for interest	18,074	21,222
Cash paid for income taxes	0	0
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$ (616)	$ 1,044

PRESENTATION OF FINANCIAL INFOR

PRESENTATION OF FINANCIAL INFORMATION	3 Months Ended
	Mar. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
PRESENTATION OF FINANCIAL INFORMATION	PRESENTATION OF FINANCIAL INFORMATION The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. These unaudited consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2020 filed with the SEC. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. Our consolidated financial position as of March 31, 2021, results of operations for the three months ended March 31, 2021 and 2020, and cash flows for the three months ended March 31, 2021 and 2020 are not necessarily indicative of the results that may be expected for an entire year or any other period. Basis of Consolidation We are a taxable wholesale electric power generation and transmission cooperative operating on a not-for-profit basis serving large portions of Colorado, Nebraska, New Mexico and Wyoming. We were incorporated under the laws of the State of Colorado in 1952. We have three classes of membership: Class A - utility full requirements members, Class B - utility partial requirements members, and non-utility members. We have forty-two electric distribution member systems who are Class A members to which we provide electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members. We have three non-utility members (“Non-Utility Members”). Our Class A members and any Class B members are collectively referred to as our “Utility Members.” Our Class A members, any Class B members, and Non-Utility Members are collectively referred to as our “Members.” The addition of Non-Utility Members in 2019 and specifically the addition of MIECO, Inc. on September 3, 2019 removed the exemption from the Federal Energy Regulatory Commission’s (“FERC”) regulation for us, thus subjecting us to full rate and transmission jurisdiction by FERC effective September 3, 2019. Our stated rate to our Class A members was filed at FERC on December 23, 2019 and was accepted by FERC on March 20, 2020. On April 30, 2021, we filed a proposed settlement agreement with FERC related to our stated rate to our Class A members. See Note 17 – Legal. We comply with the Uniform System of Accounts as prescribed by FERC. In conformity with GAAP, the accounting policies and practices applied by us in the determination of rates are also employed for financial reporting purposes. The accompanying financial statements reflect the consolidated accounts of Tri-State Generation and Transmission Association, Inc. (“Tri-State”, “we”, “our”, “us” or “the Association”), our wholly-owned and majority-owned subsidiaries, and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 16 – Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. We have eliminated all significant intercompany balances and transactions in consolidation. Jointly Owned Facilities We own undivided interests in two jointly owned generation facilities that are operated by the operating agent of each facility under joint facility ownership agreements with other utilities as tenants in common. These projects include the Yampa Project (operated by us) and the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)). Each participant in these agreements receives a portion of the total output of the generation facilities, which approximates its percentage ownership. Each participant provides its own financing for its share of each facility and accounts for its share of the cost of each facility. The operating agent for each of these projects allocates the fuel and operating expenses to each participant based upon its share of the use of the facility. Therefore, our share of the plant asset cost, interest, depreciation and other operating expenses is included in our consolidated financial statements. Our share in each jointly owned facility is as follows as of March 31, 2021 (dollars in thousands): Tri-State Electric Accumulated Construction Yampa Project - Craig Generating Station Units 1 and 2 24.00 % $ 395,810 $ 253,638 $ 418 MBPP - Laramie River Station 27.13 % 498,918 317,538 4,051 Total $ 894,728 $ 571,176 $ 4,469

ACCOUNTING FOR RATE REGULATION

ACCOUNTING FOR RATE REGULATION	3 Months Ended
	Mar. 31, 2021
Regulatory Assets and Liabilities Disclosure [Abstract]
ACCOUNTING FOR RATE REGULATION	ACCOUNTING FOR RATE REGULATION In accordance with the accounting requirements related to regulated operations, some revenues and expenses have been deferred at the discretion of our Board of Directors (“Board”), subject to FERC approval, if based on regulatory orders or other available evidence, it is probable that these amounts will be refunded or recovered through future rates. Regulatory assets are costs that we expect to recover from our Utility Members based on rates approved by the applicable authority. Regulatory liabilities represent probable future reductions in rates associated with amounts that are expected to be refunded to our Utility Members based on rates approved by the applicable authority. Expected recovery of deferred costs and returning deferred credits are based on specific ratemaking decisions by FERC or precedent for each item. We recognize regulatory assets as expenses and regulatory liabilities as operating revenue, other income, or a reduction in expense concurrent with their recovery through rates. Regulatory assets and liabilities are as follows (dollars in thousands): March 31, 2021 December 31, 2020 Regulatory assets Deferred income tax expense (1) $ 19,641 $ 19,641 Deferred prepaid lease expense – Springerville Unit 3 Lease (2) 80,851 81,424 Goodwill – J.M. Shafer (3) 45,584 46,296 Goodwill – Colowyo Coal (4) 35,903 36,161 Deferred debt prepayment transaction costs (5) 130,145 132,302 Deferred Holcomb expansion impairment loss (6) 87,651 88,819 Unrecovered plant (7) 299,705 305,625 Total regulatory assets 699,480 710,268 Regulatory liabilities Interest rate swap - realized gain (8) and other 3,155 3,293 Deferred revenues (9) 42,883 63,717 Membership withdrawal (10) 157,943 157,943 Total regulatory liabilities 203,981 224,953 Net regulatory asset $ 495,499 $ 485,315 (1) A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues. (2) Represents deferral of the loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville Unit 3”) prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation, amortization and depletion expense in the amount of $2.3 million annually through the 47-year period ending in 2056 and recovered from our Utility Members through rates. (3) Represents goodwill related to our acquisition of Thermo Cogeneration Partnership, LP in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $2.8 million annually through the 25-year period ending in 2036 and recovered from our Utility Members through rates. (4) Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $1.0 million annually through the 44-year period ending in 2056 and recovered from our Utility Members through rates. (5) Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation, amortization and depletion expense in the amount of $8.6 million annually over the 21.4-year period ending in 2036 and recovered from our Utility Members through rates. (6) Represents deferral of the impairment loss related to development costs, including costs for the option to purchase development rights for the expansion of the Holcomb Generating Station. The regulatory asset for the deferred impairment loss is being amortized to depreciation, amortization and depletion expense in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members through rates. (7) Represents deferral of the impairment losses related to the early retirement of the Nucla and Escalante Generating Stations. The deferred impairment loss for Nucla Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $11.3 million annually over the 3.3-year period ending in December 2022 and recovered from our Utility Members through rates. The deferred impairment loss for Escalante Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $11.3 million annually over the 25-year period ending in December 2045, which was the depreciable life of Escalante Generating Station, and is expected to be recovered from our Utility Members through rates. The annual amortization is expected to approximate the former annual Escalante Generating Station depreciation for the remaining life of the asset. (8) Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12-year term of the First Mortgage Obligations, Series 2017A and refunded to Utility Members through reduced rates when recognized in future periods. (9) Represents deferral of the recognition of non-member electric sales revenues. These deferred non-member electric sales revenues will be refunded to Utility Members as part of our rate stabilization measures when recognized in non-member electric sales revenue in future periods. (10) Represents the deferral of the recognition of other income related to the withdrawal of former Utility Members from membership in us. The total deferred membership withdrawal income will be refunded to Utility Members as part of our rate stabilization measures when recognized in other income in future periods.

INVESTMENTS IN OTHER ASSOCIATIO

INVESTMENTS IN OTHER ASSOCIATIONS	3 Months Ended
	Mar. 31, 2021
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
INVESTMENTS IN OTHER ASSOCIATIONS	INVESTMENTS IN OTHER ASSOCIATIONS Investments in other associations include investments in the patronage capital of other cooperatives and other required investments in the organizations. Our investment in a cooperative increases when a cooperative allocates patronage capital credits to us and it decreases when we receive a cash retirement of the allocated capital credits from the cooperative. A cooperative allocates its patronage capital credits to us based upon our patronage (amount of business done) with the cooperative. Investments in other associations are as follows (dollars in thousands): March 31, 2021 December 31, 2020 Basin Electric Power Cooperative $ 118,295 $ 118,295 National Rural Utilities Cooperative Finance Corporation - patronage capital 11,933 11,933 National Rural Utilities Cooperative Finance Corporation - capital term certificates 15,149 15,221 CoBank, ACB 12,707 11,141 Western Fuels Association, Inc. 2,200 2,283 Other 3,964 4,102 Investments in other associations $ 164,248 $ 162,975 Our investments in other associations are considered equity securities without readily determinable fair values, and as such are measured at cost minus impairment. We have evaluated these investments for indicators of impairment. There were no impairments of these investments recognized during the three months ended March 31, 2021 or during 2020.

CASH, CASH EQUIVALENTS AND REST

CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS	3 Months Ended
	Mar. 31, 2021
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS	CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTSWe consider highly liquid investments with an original maturity of three months or less to be cash equivalents. The fair value of cash equivalents approximates their carrying values due to their short-term maturity. Restricted cash and investments represent funds designated by our Board for specific uses and funds restricted by contract or other legal reasons. A portion of the funds are amounts that have been restricted by contract that are expected to be settled within one year. These funds are therefore classified as current on our consolidated statements of financial position. The other funds are for amounts restricted by contract or other legal reasons that are expected to be settled beyond one year. These funds are classified as noncurrent and are included in other assets and investments on our consolidated statements of financial position. The following table provides a reconciliation of cash, cash equivalents and restricted cash and investments reported within our consolidated statements of financial position that sum to the total of the same such amount shown in our consolidated statements of cash flows (dollars in thousands): March 31, 2021 December 31, 2020 Cash and cash equivalents $ 109,483 $ 127,187 Restricted cash and investments - current 274 205 Restricted cash and investments - noncurrent 4,546 4,682 Cash, cash equivalents and restricted cash and investments $ 114,303 $ 132,074

CONTRACT ASSETS AND CONTRACT LI

CONTRACT ASSETS AND CONTRACT LIABILITIES	3 Months Ended
	Mar. 31, 2021
Change in Contract with Customer, Asset and Liability [Abstract]
CONTRACT ASSETS AND CONTRACT LIABILITIES	CONTRACT ASSETS AND CONTRACT LIABILITIES Accounts Receivable We record accounts receivable for our unconditional rights to consideration arising from our performance under contracts with our Members and other parties. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period determined to be uncollectible. See Note 12 – Revenue. Contract liabilities (unearned revenue) A contract liability represents an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration from the customer. We have received deposits from others and these deposits are reflected in unearned revenue (included in other deferred credits and other liabilities on our consolidated statements of financial position) before revenue is recognized, resulting in contract liabilities. During the three months ended March 31, 2021, we recognized $0.1 million of this unearned revenue in other operating revenues on our consolidated statements of operations. Our contract assets and liabilities consist of the following (dollars in thousands): March 31, 2021 December 31, 2020 Accounts receivable - Utility Members $ 88,369 $ 96,637 Other accounts receivable - trade: Non-member electric sales 3,239 5,231 Other 9,855 9,785 Total other accounts receivable - trade 13,094 15,016 Other accounts receivable - nontrade 3,192 5,554 Total other accounts receivable $ 16,286 $ 20,570 Contract liabilities (unearned revenue) $ 6,301 $ 6,025

OTHER DEFERRED CHARGES

OTHER DEFERRED CHARGES	3 Months Ended
	Mar. 31, 2021
Deferred Costs [Abstract]
OTHER DEFERRED CHARGES	OTHER DEFERRED CHARGES The following other deferred charges are reflected on our consolidated statements of financial position (dollars in thousands): March 31, 2021 December 31, 2020 Preliminary surveys and investigations $ 12,142 $ 12,886 Advances to operating agents of jointly owned facilities 11,425 2,071 Operating lease right-of-use assets 7,999 7,985 Other 15,072 10,704 Total other deferred charges $ 46,638 $ 33,646 We make expenditures for preliminary surveys and investigations for the purpose of determining the feasibility of contemplated generation and transmission projects. If construction results, the preliminary survey and investigation expenditures will be reclassified to electric plant - construction work in progress. If the work is abandoned, the related preliminary survey and investigation expenditures will be charged to the appropriate operating expense account or the expense could be deferred as a regulatory asset to be recovered from our Utility Members through rates subject to approval by our Board and FERC. We make advance payments to the operating agents of jointly owned facilities to fund our share of costs expected to be incurred under each project including MBPP – Laramie River Station, and Yampa Project – Craig Generating Station Units 1 and 2. We also make advance payments to the operating agent of Springerville Unit 3. A right-of-use asset represents a lessee’s right to control the use of the underlying asset for the lease term. Right-of-use assets are included in other deferred charges and presented net of accumulated amortization. See Note 14 – Leases.

LONG-TERM DEBT

LONG-TERM DEBT	3 Months Ended
	Mar. 31, 2021
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT We have $3.1 billion of long-term debt which consists of mortgage notes payable, pollution control revenue bonds and the Springerville certificates. The mortgage notes payable and pollution control revenue bonds are secured on a parity basis by a Master First Mortgage Indenture, Deed of Trust and Security Agreement (“Master Indenture”) except for one unsecured note in the amount of $17.7 million as of March 31, 2021. Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Unit 3. All long-term debt contains certain restrictive financial covenants, including a debt service ratio requirement on an annual basis and an equity to capitalization ratio requirement of at least 18 percent at the end of each fiscal year. Other than the Springerville certificates that has a debt service ratio requirement of at least 1.02 on an annual basis, all other long-term debt contains a debt service ratio requirement of at least 1.10 on an annual basis. We have a secured revolving credit facility with National Rural Utilities Cooperative Finance Corporation (“CFC”), as lead arranger and administrative agent, in the amount of $650 million (“Revolving Credit Agreement”) that expires on April 25, 2023 and includes a swingline sublimit of $100 million, a letter of credit sublimit of $75 million, and a commercial paper back-up sublimit of $500 million. As of March 31, 2021, we had $650.0 million in availability under the Revolving Credit Agreement. Long-term debt consists of the following (dollars in thousands): March 31, 2021 December 31, 2020 Total debt $ 3,262,606 $ 3,308,715 Less debt issuance costs (24,963) (25,590) Less debt discounts (9,595) (9,659) Plus debt premiums 13,967 14,302 Total debt adjusted for debt issuance costs, discounts and premiums 3,242,015 3,287,768 Less current maturities (94,592) (87,587) Long-term debt $ 3,147,423 $ 3,200,181

SHORT-TERM BORROWINGS

SHORT-TERM BORROWINGS	3 Months Ended
	Mar. 31, 2021
Short-term Debt [Abstract]
SHORT-TERM BORROWINGS	SHORT-TERM BORROWINGS We have a commercial paper program under which we issue unsecured commercial paper in aggregate amounts not exceeding the commercial paper back-up sublimit under our Revolving Credit Agreement, which is the lesser of $500 million or the amount available under our Revolving Credit Agreement. As of March 31, 2021 and December 31, 2020, we had no commercial paper outstanding. At March 31, 2021, $500.0 million of the commercial paper back-up sublimit remained available under the Revolving Credit Agreement. See Note 7 – Long-Term Debt.

ASSET RETIREMENT AND ENVIRONMEN

ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS	3 Months Ended
	Mar. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS	ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS We account for current obligations associated with the future retirement of tangible long-lived assets and environmental reclamation in accordance with the accounting guidance relating to asset retirement and environmental obligations. This guidance requires that legal obligations associated with the retirement of long-lived assets be recognized at fair value at the time the liability is incurred and capitalized as part of the related long-lived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense and the capitalized cost of the long-lived asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. In the absence of quoted market prices, we determine fair value by using present value techniques in which estimates of future cash flows associated with retirement activities are discounted using a credit adjusted risk-free rate and market risk premium. Upon settlement of an asset retirement obligation, we will apply payment against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability. Environmental reclamation costs are accrued based on management’s best estimate at the end of each period of the costs expected to be incurred. Such cost estimates may include ongoing care, maintenance and monitoring costs. Changes in reclamation estimates are reflected in earnings in the period an estimate is revised. Estimates of future expenditures for environmental reclamation obligations are not discounted. Coal mines: We have asset retirement obligations for the final reclamation costs and environmental obligations for post-reclamation monitoring related to the Colowyo Mine and the New Horizon Mine. The New Horizon Mine is currently in post-reclamation monitoring. One pit at the Colowyo Mine began final reclamation in 2019 with the other remaining pits still being actively mined. Generation: We have asset retirement obligations related to equipment, dams, ponds, wells and underground storage tanks at the generating stations. Aggregate carrying amounts of asset retirement obligations and environmental reclamation obligations are as follows (dollars in thousands): Three Months Ended 2021 Obligations at beginning of period $ 138,089 Liabilities incurred — Liabilities settled (107) Accretion expense 803 Change in cash flow estimate — Total obligations at end of period $ 138,785 Less current obligations at end of period (11,080) Long-term obligations at end of period $ 127,705 We also have asset retirement obligations with indeterminate settlement dates. These are made up primarily of obligations attached to transmission and other easements that are considered by us to be operated in perpetuity and therefore the measurement of the obligation is not possible. A liability will be recognized in the period in which sufficient information exists to estimate a range of potential settlement dates as is needed to employ a present value technique to estimate fair value.

OTHER DEFERRED CREDITS AND OTHE

OTHER DEFERRED CREDITS AND OTHER LIABILITIES	3 Months Ended
	Mar. 31, 2021
Deferred Credits and Other Liabilities [Abstract]
OTHER DEFERRED CREDITS AND OTHER LIABILITIES	OTHER DEFERRED CREDITS AND OTHER LIABILITIES The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands): March 31, 2021 December 31, 2020 Transmission easements $ 19,621 $ 19,983 Operating lease liabilities - noncurrent 1,761 1,590 Contract liabilities (unearned revenue) - noncurrent 3,611 3,702 Customer deposits 8,935 7,712 Financial liabilities - reclamation 11,924 12,081 Deposits associated with generator interconnection requests 17,130 — Other 9,419 9,532 Total other deferred credits and other liabilities $ 72,401 $ 54,600 In 2015, we renewed transmission right of way easements on tribal nation lands where certain of our electric transmission lines are located. $29.4 million will be paid by us for these easements from 2021 through the individual easement terms ending between 2036 and 2040. The present values for the remaining easement payments were $19.6 and $20.0 million as of March 31, 2021 and December 31, 2020, respectively, which are recorded as other deferred credits and other liabilities. A lease liability represents a lessee’s obligation to make lease payments over the lease term. The long-term portion of our lease liabilities are included in other deferred credits and other liabilities and the current portion of our lease liabilities are included in current liabilities. See Note 14 – Leases. A contract liability represents an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration from the customer. We have received deposits from others and these deposits are reflected in contract liabilities (unearned revenue) until recognized in other operating revenues over the life of the agreement. We have received deposits from various parties and those that may still be required to be returned are a liability and these are reflected in customer deposits.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	3 Months Ended
	Mar. 31, 2021
Retirement Benefits [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS Postretirement Benefits Other Than Pensions We sponsor three medical plans for all non-bargaining unit employees under the age of 65. Two of the plans provide postretirement medical benefits to full-time non-bargaining unit employees and retirees who receive benefits under those plans, who have attained age 55, and who elect to participate. All three of these non-bargaining unit medical plans offer postemployment medical benefits to employees on long-term disability. The plans were unfunded at March 31, 2021, are contributory (with retiree premium contributions equivalent to employee premiums, adjusted annually) and contain other cost-sharing features such as deductibles. As of June 30, 2021, the plans will cease to provide postretirement medical benefits for employees who retire after June 30, 2021. The postretirement medical benefit and postemployment medical benefit obligations are determined annually (during the fourth quarter) by an independent actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands): Three Months Ended 2021 Postretirement medical benefit obligation at beginning of period $ 9,985 Service cost 150 Interest cost 65 Benefit payments (net of contributions by participants) (148) Postretirement medical benefit obligation at end of period $ 10,052 Postemployment medical benefit obligation at end of period 419 Total postretirement and postemployment medical obligations at end of period $ 10,471 The service cost component of our net periodic benefit cost is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations. In accordance with the accounting standard related to postretirement benefits other than pensions, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other income on our consolidated statements of financial position. If the unrecognized amount is in excess of 10 percent of the projected benefit obligation, amounts are reclassified out of accumulated other comprehensive income and included in net income as the excess is amortized over the average remaining service lives of the active plan participants. Unrecognized actuarial gains and losses have been determined per actuarial studies for the postretirement medical benefit obligation. The net unrecognized actuarial gains and losses related to the postretirement medical benefit obligations are included in accumulated other comprehensive income as follows (dollars in thousands): Three Months Ended 2021 Accumulated other comprehensive loss at beginning of period $ (841) Amortization of prior service credit into other income (20) Accumulated other comprehensive loss at end of period $ (861) Defined Benefit Plans We participate in the NRECA Pension Restoration Plan and the NRECA Executive Benefit Restoration Plan, both of which are intended to provide a supplemental benefit to the defined benefit plan for an eligible group of highly compensated employees. Eligible employees include the Chief Executive Officer and any other employees that become eligible. All our executive employees currently participate in one of the following pension restoration plans: the NRECA Pension Restoration Plan or the NRECA Executive Benefit Restoration Plan. Eligibility is determined annually and is based on January 1 base salary that exceeds the limits of the defined benefit plan. As of April 30, 2021, the plans will cease to add new participants and no new executives will be eligible for the plan. The NRECA Executive Benefit Restoration Plan obligations are determined annually (during the first quarter of the subsequent year) by an NRECA actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands): Three Months Ended 2021 Executive benefit restoration obligation at beginning of period $ 7,379 Service cost 137 Interest cost 53 Actuarial loss 1,121 Executive benefit restoration at end of period $ 8,690 Fair value of plan assets at beginning of period $ 6,955 Employer contributions 403 Actual return on plan assets $ (41) Fair value of plan assets at end of period $ 7,317 Net liability recognized $ 1,373 The service cost component of our net periodic benefit cost is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations. In December 2020, we established an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary. In accordance with the accounting standard related to defined benefit pension plans, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other income on our consolidated statements of financial position. If the unrecognized amount is in excess of 10 percent of the projected benefit obligation, amounts are reclassified out of accumulated other comprehensive income and included in net income as the excess is amortized over the average remaining service lives of the active plan participants. Unrecognized actuarial gains and losses have been determined per actuarial studies for the executive benefit restoration obligation. The net unrecognized actuarial gains and losses related to the executive benefit restoration obligations are included in accumulated other comprehensive income as follows (dollars in thousands): Three Months Ended 2021 Accumulated other comprehensive loss at beginning of period $ (4,873) Amortization of prior service cost into other income 220 Amortization of actuarial loss 171 Curtailment and settlement 141 Unrecognized actuarial loss (1,121) Accumulated other comprehensive loss at end of period $ (5,462)

REVENUE

REVENUE	3 Months Ended
	Mar. 31, 2021
Revenue from Contract with Customer [Abstract]
REVENUE	REVENUE Revenue from Contracts with Customers Our revenues are derived primarily from the sale of electric power to our Utility Members pursuant to long-term wholesale electric service contracts. Our contracts with our 42 Utility Members extend through 2050. Member electric sales Revenues from electric power sales to our Utility Members are primarily from our Class A rate schedule filed with FERC. Our Class A rate schedule for electric power sales to our Utility Members consist of three billing components: an energy rate and two demand rates. Our Class A rate schedule is variable and is approved by our Board and FERC. Energy and demand have the same pattern of transfer to our Utility Members and are both measurements of the electric power provided to our Utility Members. Therefore, the provision of electric power to our Utility Members is one performance obligation. Prior to our Utility Members’ requirement for electric power, we do not have a contractual right to consideration as we are not obligated to provide electric power until the Utility Member requires each incremental unit of electric power. We transfer control of the electric power to our Utility Members over time and our Utility Members simultaneously receive and consume the benefits of the electric power. Progress toward completion of our performance obligation is measured using the output method, meter readings are taken at the end of each month for billing purposes, energy and demand are determined after the meter readings and Utility Members are invoiced based on the meter reading. Payments from our Utility Members are received in accordance with the wholesale electric service contracts’ terms, which is less than 30 days from the invoice date. Utility Member electric sales revenue is recorded as Utility Member electric sales on our consolidated statements of operations and Accounts receivable – Utility Members on our consolidated statements of financial position. In addition to our Utility Member electric sales, we have non-member electric sales and other operating revenue which consist of several revenue streams. The following revenue is reflected on our consolidated statements of operations as follows (dollars in thousands): Three Months Ended March 31, 2021 2020 Non-member electric sales: Long-term contracts $ 8,706 $ 12,144 Short-term contracts 8,634 3,669 Recognition of deferred revenue 20,834 — Other 15,000 10,890 Total non-member electric sales and other operating revenue $ 53,174 $ 26,703 Non-member electric sales Revenues from electric power sales to non-members are primarily from long-term contracts and short-term market sales. Prior to our customers’ demand for energy, we do not have a contractual right to consideration as we are not obligated to provide energy until the customer demands each incremental unit of energy. We transfer control of the energy to our customer over time and our customer simultaneously receives and consumes the benefits of the electric power. Progress toward completion of our performance obligation is measured using the output method. Payments are received in accordance with the contract terms, which is less than 30 days after the invoice is received by the customer. Other operating revenue Other operating revenue consists primarily of wheeling, transmission, water and coal sales revenue . Other operating revenue also includes revenue we receive from two of our Non-Utility Members. Wheeling revenue is earned when we charge other energy companies for transmitting electricity over our transmission lines (payments are received in accordance with the contract terms which is within 20 days of the date the invoice is received). Transmission revenue is from Southwest Power Pool’s scheduling of transmission across our transmission assets in the Eastern Interconnection because of our membership in it (Southwest Power Pool collects the revenue from the customer and pays us for the scheduling, system control, dispatch transmission service, and the annual transmission revenue requirement). Water revenue is derived from supplying water resources to a paper manufacturer located adjacent to the Escalante Generating Station (payments from the customer are received in accordance with the contract terms which is less than 15 days from the invoice date). Each of these services or goods are provided over time and progress toward completion of our performance obligations are measured using the output method. Coal sales revenue results from the sale of coal from the Colowyo Mine to third parties. We have an obligation to deliver coal and progress of completion toward our performance obligation is measured using the output method. Our performance obligation is completed as coal is delivered.

INCOME TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2021
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXESWe are a taxable cooperative subject to federal and state taxation. As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital. We utilize the liability method of accounting for income taxes, which requires that deferred tax assets and liabilities be determined based on the expected future income tax consequences of events that have been recognized in the consolidated financial statements. Effective January 1, 2020, we adopted the normalization method of recognizing deferred income taxes pursuant to FERC regulation. Under the normalization method, changes in deferred tax assets or liabilities result in deferred income tax expense (benefit) and any recorded income tax expense (benefit) therefore includes both the current income tax expense (benefit) and the deferred income tax expense (benefit). Our subsidiaries are not subject to FERC regulation and continue to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability, as approved by our Board. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be settled or received through future rate revenues. Our consolidated statements of operations included an income tax expense of $0.1 million for the three months ended March 31, 2021 and an income tax benefit of $0.2 million for the comparable period in 2020.

LEASES

LEASES	3 Months Ended
	Mar. 31, 2021
Leases [Abstract]
LEASES	LEASES Leasing Arrangements As Lessee We determine if an arrangement is a lease upon commencement of the contract. If an arrangement is determined to be a long-term lease (greater than 12 months), we recognize a right-of-use asset and lease liability based on the present value of the future minimum lease payments over the lease term at the commencement date. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. Our lease terms may also include options to extend or terminate the lease when it is reasonably certain that we will exercise those options. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. Right-of-use assets are included in other deferred charges, the current portion of lease liabilities is included in current liabilities and the long-term portion of lease liabilities is included in other deferred credits and other liabilities on our consolidated statements of financial position. We have elected to apply the short-term lease exception for contracts that have a lease term of twelve months or less and do not include an option to purchase the underlying asset. Therefore, we do not recognize a right-of-use asset or lease liability for such contracts. We recognize short-term lease payments as expense on a straight-line basis over the lease term. Variable lease payments that do not depend on an index or rate are recognized as expense. We have lease agreements as lessee for the right to use various facilities and operational assets. Rent expense for all short-term and long-term operating leases was $1.0 million for the three months ended March 31, 2021 and $0.9 million for the comparable period in 2020. Rent expense is included in operating expenses on our consolidated statements of operations. As of March 31, 2021, there were no arrangements accounted for as finance leases. Our consolidated statements of financial position include the following lease components (dollars in thousands): March 31, 2021 December 31, 2020 Operating leases Operating lease right-of-use assets $ 9,331 $ 9,223 Less: Accumulated amortization (1,332) (1,238) Net operating lease right-of-use assets $ 7,999 $ 7,985 Operating lease liabilities - current $ (499) $ (526) Operating lease liabilities - noncurrent (1,761) (1,590) Total operating lease liabilities $ (2,260) $ (2,116) Operating leases Weighted average remaining lease term (years) 7.7 7.6 Weighted average discount rate 3.85 % 3.84 % Future expected minimum lease commitments under operating leases are as follows (dollars in thousands): Year 1 $ 527 Year 2 365 Year 3 336 Year 4 286 Year 5 100 Thereafter 690 Total lease payments $ 2,304 Less imputed interest (44) Total $ 2,260 Leasing Arrangements As Lessor We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $1.8 million and $1.6 million for the three months ended March 31, 2021 and 2020, respectively, are included in other operating revenue on our consolidated statements of operations.

FAIR VALUE

FAIR VALUE	3 Months Ended
	Mar. 31, 2021
Fair Value Disclosures [Abstract]
FAIR VALUE	FAIR VALUE Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal or in the most advantageous market when no principal market exists. The fair value measurement accounting guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability (market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress). In considering market participant assumptions in fair value measurements, a three-tier fair value hierarchy for measuring fair value was established which prioritizes the inputs used in measuring fair value as follows: Level 1 inputs are based upon quoted prices for identical instruments traded in active (exchange-traded) markets. Valuations are obtained from readily available pricing sources for market transactions (observable market data) involving identical assets or liabilities. Level 2 inputs are based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-based valuation techniques (such as option pricing models, discounted cash flow models) for which all significant assumptions are observable in the market. Level 3 inputs consist of unobservable market data which is typically based on an entity’s own assumptions of what a market participant would use in pricing an asset or liability as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Executive Benefit Restoration Plan Trust In December 2020, we established an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary. The trust consists of investments in equity and debt securities and are measured at fair value on a recurring basis. Changes in the fair value of investments in equity securities are recognized in earnings and changes in fair value of investments in debt securities classified as available-for-sale are recognized in other comprehensive income until realized. The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The cost and fair values of our marketable securities are as follows (dollars in thousands): March 31, 2021 December 31, 2020 Cost Estimated Cost Estimated EBR Trust investments $ 7,384 $ 7,316 $ 6,955 $ 6,955 Marketable Securities We hold marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds. These securities are measured at fair value on a recurring basis with changes in fair value recognized in earnings. The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The cost and fair values of our marketable securities are as follows (dollars in thousands): March 31, 2021 December 31, 2020 Cost Estimated Cost Estimated Marketable securities $ 493 $ 503 $ 491 $ 478 Cash Equivalents We invest portions of our cash and cash equivalents in commercial paper, money market funds, and other highly liquid investments. The fair value of these investments approximates our cost basis in the investments. In aggregate, the fair value was $88.2 million as of March 31, 2021 and $94.6 million as of December 31, 2020. Debt The fair values of debt were estimated using discounted cash flow analyses based on our current incremental borrowing rates for similar types of borrowing arrangements. These valuation assumptions utilize observable inputs based on market data obtained from independent sources and are therefore considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market corroborated inputs). The principal amounts and fair values of our debt are as follows (dollars in thousands): March 31, 2021 December 31, 2020 Principal Estimated Principal Estimated Total debt $ 3,262,606 $ 3,748,334 $ 3,308,715 $ 3,908,497

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	3 Months Ended
	Mar. 31, 2021
Variable Interest Entity or Potential VIE, Information Unavailability, Disclosures [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES The following is a description of our financial interests in variable interest entities that we consider significant. This includes an entity for which we are determined to be the primary beneficiary and therefore consolidate and also entities for which we are not the primary beneficiary and therefore do not consolidate. Consolidated Variable Interest Entity Springerville Partnership: We own a 51 percent equity interest, including the 1 percent general partner equity interest, in the Springerville Partnership, which is the 100 percent owner of Springerville Unit 3 Holding LLC (“Owner Lessor”). The Owner Lessor is the owner of the Springerville Unit 3. We, as general partner of the Springerville Partnership, have the full, exclusive and complete right, power and discretion to operate, manage and control the affairs of the Springerville Partnership and take certain actions necessary to maintain the Springerville Partnership in good standing without the consent of the limited partners. Additionally, the Owner Lessor has historically not demonstrated an ability to finance its activities without additional financial support. The financial support is provided by our remittance of lease payments in order to permit the Owner Lessor, the holder of the Springerville Unit 3 assets, to pay the debt obligations and equity returns of the Springerville Partnership. We have the primary risk (expense) exposure in operating the Springerville Unit 3 assets and are responsible for 100 percent of the operation, maintenance and capital expenditures of Springerville Unit 3 and the decisions related to those expenditures including budgeting, financing and dispatch of power. Based on all these facts, it was determined that we are the primary beneficiary of the Owner Lessor. Therefore, the Springerville Partnership and Owner Lessor have been consolidated by us. Assets and liabilities of the Springerville Partnership that are included in our consolidated statements of financial position are as follows (dollars in thousands): March 31, 2021 December 31, 2020 Net electric plant $ 753,739 $ 758,273 Noncontrolling interest 113,807 114,852 Long-term debt 301,066 342,355 Accrued interest 3,488 9,942 Our consolidated statements of operations include the following Springerville Partnership expenses for the three months ended March 31, 2021 and 2020 (dollars in thousands): March 31, 2021 2020 Depreciation, amortization and depletion $ 4,534 $ 4,534 Interest 5,185 5,861 The revenue associated with the Springerville Partnership lease has been eliminated in consolidation. Income, losses and cash flows of the Springerville Partnership are allocated to the general and limited partners based on their equity ownership percentages. The net income or loss attributable to the 49 percent noncontrolling equity interest in the Springerville Partnership is reflected on our consolidated statements of operations.

LEGAL

LEGAL	3 Months Ended
	Mar. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
LEGAL	LEGAL Other than as disclosed below, we do not expect any litigation or proceeding pending or threatened against us to have a potential material effect on our financial condition, results of operations or cash flows. FERC Tariff and Declaratory Order: Because of increased pressure by states to regulate our rates and charges with impact in other states setting up untenable conflict, we sought consistent federal jurisdiction by FERC. This was accomplished with the addition of non-cooperative members in 2019, specifically MIECO, Inc. as a Non-Utility Member on September 3, 2019. On the same date, we became FERC jurisdictional for our Utility Member rates, transmission service, and our market based rates. We filed our tariff for wholesale electric service and transmission at FERC in December 2019. The request was made to FERC to make the new tariffs retroactive to September 3, 2019. In addition, on December 23, 2019, we filed our Petition for Declaratory Order ("Jurisdictional PDO") with FERC, EL20-16-000, asking FERC to confirm our jurisdiction under the Federal Power Act and that FERC’s jurisdiction preempts the jurisdiction of the Colorado Public Utilities Commission ("COPUC") to address any rate related issues, including the complaints filed by United Power, Inc. ("United Power") and La Plata Electric Association ("LPEA") with the COPUC. On March 20, 2020, FERC issued orders regarding our Jurisdictional PDO and our tariff filings. FERC’s orders generally accepted our tariff filings and recognized that we became FERC jurisdictional on September 3, 2019, but did not make the tariffs retroactive to September 3, 2019. However, FERC specifically provided that no refunds are due on our Utility Member rates and our transmission service rates prior to March 26, 2020. FERC did not impose any civil penalties on us. FERC also did not determine that our Utility Member rates and transmission service rates were just and reasonable and ordered 206 proceedings to determine the justness and reasonableness of our rates and wholesale electric service contracts. FERC also rejected our Board Policy 115 (“BP 115”) and member project contracts related to our Utility Members’ election to provide up to 5 percent of their electric power requirements pursuant to their wholesale electric service contracts on the grounds that the initial filing was incomplete without Board Policy 101 (“BP 101”) related to the self-supply in excess of the 5 percent annual allowance. The tariff rates were referred to an administrative law judges to encourage settlement of material issues and to hold a hearings if settlements is not reached. Any refunds to the applicable tariff rates would only apply for sales after March 26, 2020. The settlement proceedings for both our Utility Member rates and our transmission service rates are continuing. On April 30, 2021, we filed a proposed settlement agreement related to our Utility Member stated rate, including BP 115, BP 101, and Board Policy 119 (“BP 119”), with FERC for approval, as further discussed below. FERC’s March 20, 2020 order regarding our Jurisdictional PDO denied our requested declaration regarding the preemption of the United Power and LPEA proceeding at the COPUC stating the proceeding was not currently preempted. On April 13, 2020, we filed a request for rehearing limited to the issue of preemption of the United Power and LPEA proceeding at the COPUC related to the contract termination payment amount as described in our Jurisdictional PDO. Requests for rehearing related to both the Jurisdictional PDO and tariff filings were filed with FERC by other parties, including United Power. On August 28, 2020, FERC issued an order (“August 28 Order”) on rehearing related to our Jurisdictional PDO which modified its March 20, 2020 decision by finding exclusive jurisdiction over our contract termination payments and preempting the jurisdiction of the COPUC as of September 3, 2019. The August 28 Order also set aside requests for rehearing filed with FERC by other parties related to the Jurisdictional PDO. Requests for rehearing related to FERC’s August 28 Order were filed with FERC by United Power and LPEA. On October 28, 2020, FERC issued an order denying the requests for rehearing filed by United Power and LPEA. On July 1, 2020, we re-submitted our BP 101, BP 115, and all existing member project contracts with FERC for acceptance and on August 28, 2020 FERC accepted the filings effective August 31, 2020. FERC also ordered a 206 proceeding to determine whether our July 1 filed documents are just and reasonable and set them for settlement and hearing procedures, which were consolidated with the ongoing settlement and hearing procedures in effect for our member rates docket. FERC also established a refund effective date related to our July 1 filed documents of September 1, 2020. A request for rehearing related to this FERC order was filed with FERC by United Power. In November 2020, FERC issued an order addressing the arguments for rehearing raised by United Power and modified its August 28, 2020 order with the same result in the proceeding. United Power has filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit Court of Appeals") related to FERC’s acceptance of our July 1 filed documents and such matter is being held in abeyance pending resolution of the Jurisdictional PDO appeal discussed below. On October 19, 2020, we filed our BP 119 related to our community solar program that provides for our Utility Members to develop community solar projects up to specified annual output limits separate from and in addition to the 5 percent self-supply provision of the wholesale electric service contracts and our first community solar contract with a Utility Member with FERC for acceptance. On December 18, 2020, FERC accepted BP 119 and the community solar contract, to be effective December 19, 2020, subject to refund. FERC referred it to FERC’s hearing and settlement judge procedures, which were consolidated with the ongoing settlement and hearing procedures in effect for our member rates docket. On July 13, 2020, we filed a petition for review with the D.C. Circuit Court of Appeals to protect our interest, and requested review of FERC’s order granting in part and denying in part our Jurisdictional PDO and FERC’s order granting rehearings for further consideration. Petitions for review related to both the Jurisdictional PDO and tariff filings have been filed with the D.C. Circuit Court of Appeals by other parties, including United Power. On September 18, 2020, FERC filed to hold the appeals in abeyance. On September 29, 2020, an order was issued considering the motion to hold the case in abeyance, directing the parties to file motions to govern future proceedings by January 11, 2021. FERC, United Power, and the other parties reached agreement on the procedures and schedule for the Jurisdictional PDO and abeyance on all non-Jurisdictional PDO matters and such filing was made to the D.C. Circuit Court of Appeals. On April 30, 2021, we filed a proposed settlement agreement related to our Utility Member stated rate, including our wholesale electric service contracts, BP 115, BP 101, and BP 119, with FERC for approval. With the exception of four reserved issues contingent on United Power being a settling party, the proposed settlement resolves all issues set for hearing and settlement procedures related to our Utility Member rates. The proposed settlement provides for us to implement a two-stage, graduated reduction in the charges making up our Class A rate schedule of two percent starting from March 1, 2021 until the first anniversary and four percent reduction (additional two percent reduction from current rates) thereafter until the date a new Class A wholesale rate schedule is approved by FERC and goes into effect. The proposed settlement rates will remain in effect at least through May 31, 2023 and during such time period, we and the settlement parties have agreed, with limited exceptions, to a moratorium on any filings related to our Class A rate schedule, including any rate increases to our Class A rate schedule. We have also agreed to file a new Class A rate schedule after May 31, 2023 and prior to September 1, 2023. During the moratorium, we will establish a rate design committee to oversee the development of the new rate. Three of the reserved issues are related to the transmission component of our rates and the fourth relates to our community solar program. Additionally, with the exception of one reserved issue regarding transmission demand charges applicable to certain electric storage resources, each of the reserved issues will have prospective effect only, with the intent that any FERC rulings would be implemented in future rate filings. This proposed settlement agreement is subject to FERC’s approval. We also filed a motion with FERC’s Chief Judge seeking immediate implementation, effective as of March 1, 2021, of the two percent rate reduction, pending FERC’s approval of the proposed settlement. On May 5, 2021, the Chief Judge issued an order granting implementation of the proposed settlement rates effective as of March 1, 2021 pending FERC’s consideration of the proposed settlement agreement. In connection with the proposed settlement anticipated to become effected as of March 1, 2021, our Utility Member electric sales revenue and results of operations does not include approximately $1.7 million of revenue associated with the two percent rate reduction for March 2021. Such amount is being held in reserve. It is not possible to predict if FERC will require us to refund amounts to our customers for sales after March 26, 2020 on outstanding issues, if FERC will approve our current practices regarding use of regulatory assets are just and reasonable, if FERC will accept our proposed settlement agreement filed on April 30, 2021,if settlements will be reached without a hearing on outstanding issues, or to estimate any liability associated with these matters. In addition, we cannot predict the outcome of the 206 proceedings or any petitions for review filed with the D.C. Circuit Court of Appeals. LPEA and United Power COPUC Complaints . Pursuant to our Bylaws, a Utility Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as our Board may prescribe provided, however, that no Utility Member shall be permitted to withdraw until it has met all its contractual obligations to us, including all obligations under its wholesale electric service contract with us. On November 5, 2019, LPEA filed a formal complaint with the COPUC alleging that we hindered LPEA’s ability to seek withdrawal from us. On November 6, 2019, United Power filed a formal complaint with the COPUC, alleging that we hindered United Power’s ability to explore its power supply options by either withdrawing from us or continuing as a Utility Member under a partial requirements contract. On November 20, 2019, the COPUC consolidated the two proceeding into one, 19F-0621E. A hearing was held on May 18-20, 2020. On July 10, 2020, the administrative law judge issued a recommended decision, but the COPUC on its own motion stayed the recommended decision. On September 18, 2020, LPEA and United Power filed a Joint Motion to Lodge FERC’s August 28 Order, and asserting additional corporate law arguments related to the legality of our addition of Non-Utility Members. We filed a response on September 29, 2020. On October 22, 2020, the COPUC determined that COPUC’s jurisdiction over United Power and LPEA’s complaints was preempted by FERC, the COPUC does not have jurisdiction over corporate law matters, and dismissed both complaints without prejudice. On November 25, 2020, LPEA and United Power jointly filed an application for rehearing, reargument, and reconsideration with the COPUC of its October 22, 2020 decision. The COPUC denied LPEA's and United Power's November 25 application, which denial became final on December 28, 2020. On January 27, 2021, United Power filed a Writ for Certiorari or Judicial Review, an appeal, in the Denver County District Court, 2021CV30325, of the COPUC's decision to dismiss United Power's complaint. On February 17, 2021, the Denver County District Court granted our unopposed motion to intervene as a defendant in United Power’s appeal of the COPUC’s dismissal. On April 30, 2021, United Power filed its opening brief of petitioner. It is not possible to predict the outcome in this matter. United Power's Adams District Court Complaints : On May 4, 2020, United Power filed a Complaint for Declaratory Judgement and Damages in the Adams County District Court, 2020CV30649, against us and our three Non-Utility Members alleging, among other things, that the April 2019 Bylaws amendment that allows our Board to establish one or more classes of membership in addition to the then existing all-requirements class of membership is void, the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are also void, that we have breached the wholesale electric service contract with United Power, and that we and our three Non-Utility Members conspired to deprive the COPUC of jurisdiction over the contract termination payment of our Colorado Utility Members. On June 20, 2020, we filed our answer denying United Power’s allegations and request for relief, and asked the court to dismiss United Power’s claims. We asserted counterclaims against United Power, and are seeking relief from United Power’s breach of our Bylaws and declaratory judgement that the April 2019 Bylaws amendment and the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are valid. On June 20, 2020, the three Non-Utility Members filed a joint motion to dismiss. United Power filed its response on July 30, 2020. On December 10, 2020, the Non-Utility Members motion to dismiss was granted. On December 23, 2020, United Power sought to amend its May 2020 compliant to add LPEA as an additional plaintiff and to add the claims from its November 2020 complaint, discussed below, into its amended complaint and to dismiss the November 2020 complaint against us. The court has not yet decided whether United Power will be granted leave to file its amended complaint. In addition, on November 23, 2020, United Power filed a Complaint for Declaratory Relief in the Adams County District Court, 2020CV031496, against us seeking for the court to declare that our addition of the Non-Utility Members violated Colorado law. On December 11, 2020, we moved to dismiss United Power's November 2020 compliant because it repeats the claims pending in the May 2020 complaint proceeding. The court has not yet ruled on our motion. It is not possible to predict the outcome of these matters or whether we will incur any liability in connection with these matters.

PRESENTATION OF FINANCIAL INF_2

PRESENTATION OF FINANCIAL INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of jointly owned facilities	Our share in each jointly owned facility is as follows as of March 31, 2021 (dollars in thousands): Tri-State Electric Accumulated Construction Yampa Project - Craig Generating Station Units 1 and 2 24.00 % $ 395,810 $ 253,638 $ 418 MBPP - Laramie River Station 27.13 % 498,918 317,538 4,051 Total $ 894,728 $ 571,176 $ 4,469

ACCOUNTING FOR RATE REGULATION

ACCOUNTING FOR RATE REGULATION (Tables)	3 Months Ended
	Mar. 31, 2021
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets and liabilities	Regulatory assets and liabilities are as follows (dollars in thousands): March 31, 2021 December 31, 2020 Regulatory assets Deferred income tax expense (1) $ 19,641 $ 19,641 Deferred prepaid lease expense – Springerville Unit 3 Lease (2) 80,851 81,424 Goodwill – J.M. Shafer (3) 45,584 46,296 Goodwill – Colowyo Coal (4) 35,903 36,161 Deferred debt prepayment transaction costs (5) 130,145 132,302 Deferred Holcomb expansion impairment loss (6) 87,651 88,819 Unrecovered plant (7) 299,705 305,625 Total regulatory assets 699,480 710,268 Regulatory liabilities Interest rate swap - realized gain (8) and other 3,155 3,293 Deferred revenues (9) 42,883 63,717 Membership withdrawal (10) 157,943 157,943 Total regulatory liabilities 203,981 224,953 Net regulatory asset $ 495,499 $ 485,315 (1) A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues. (2) Represents deferral of the loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville Unit 3”) prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation, amortization and depletion expense in the amount of $2.3 million annually through the 47-year period ending in 2056 and recovered from our Utility Members through rates. (3) Represents goodwill related to our acquisition of Thermo Cogeneration Partnership, LP in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $2.8 million annually through the 25-year period ending in 2036 and recovered from our Utility Members through rates. (4) Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $1.0 million annually through the 44-year period ending in 2056 and recovered from our Utility Members through rates. (5) Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation, amortization and depletion expense in the amount of $8.6 million annually over the 21.4-year period ending in 2036 and recovered from our Utility Members through rates. (6) Represents deferral of the impairment loss related to development costs, including costs for the option to purchase development rights for the expansion of the Holcomb Generating Station. The regulatory asset for the deferred impairment loss is being amortized to depreciation, amortization and depletion expense in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members through rates. (7) Represents deferral of the impairment losses related to the early retirement of the Nucla and Escalante Generating Stations. The deferred impairment loss for Nucla Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $11.3 million annually over the 3.3-year period ending in December 2022 and recovered from our Utility Members through rates. The deferred impairment loss for Escalante Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $11.3 million annually over the 25-year period ending in December 2045, which was the depreciable life of Escalante Generating Station, and is expected to be recovered from our Utility Members through rates. The annual amortization is expected to approximate the former annual Escalante Generating Station depreciation for the remaining life of the asset. (8) Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12-year term of the First Mortgage Obligations, Series 2017A and refunded to Utility Members through reduced rates when recognized in future periods. (9) Represents deferral of the recognition of non-member electric sales revenues. These deferred non-member electric sales revenues will be refunded to Utility Members as part of our rate stabilization measures when recognized in non-member electric sales revenue in future periods. (10) Represents the deferral of the recognition of other income related to the withdrawal of former Utility Members from membership in us. The total deferred membership withdrawal income will be refunded to Utility Members as part of our rate stabilization measures when recognized in other income in future periods.

INVESTMENTS IN OTHER ASSOCIAT_2

INVESTMENTS IN OTHER ASSOCIATIONS (Tables)	3 Months Ended
	Mar. 31, 2021
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Schedule of investments in other associations	Investments in other associations are as follows (dollars in thousands): March 31, 2021 December 31, 2020 Basin Electric Power Cooperative $ 118,295 $ 118,295 National Rural Utilities Cooperative Finance Corporation - patronage capital 11,933 11,933 National Rural Utilities Cooperative Finance Corporation - capital term certificates 15,149 15,221 CoBank, ACB 12,707 11,141 Western Fuels Association, Inc. 2,200 2,283 Other 3,964 4,102 Investments in other associations $ 164,248 $ 162,975

CASH, CASH EQUIVALENTS AND RE_2

CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS (Tables)	3 Months Ended
	Mar. 31, 2021
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Schedule of cash, cash equivalents and restricted cash and investments	The following table provides a reconciliation of cash, cash equivalents and restricted cash and investments reported within our consolidated statements of financial position that sum to the total of the same such amount shown in our consolidated statements of cash flows (dollars in thousands): March 31, 2021 December 31, 2020 Cash and cash equivalents $ 109,483 $ 127,187 Restricted cash and investments - current 274 205 Restricted cash and investments - noncurrent 4,546 4,682 Cash, cash equivalents and restricted cash and investments $ 114,303 $ 132,074

CONTRACT ASSETS AND CONTRACT _2

CONTRACT ASSETS AND CONTRACT LIABILITIES (Tables)	3 Months Ended
	Mar. 31, 2021
Change in Contract with Customer, Asset and Liability [Abstract]
Schedule of contract assets and liabilities	Our contract assets and liabilities consist of the following (dollars in thousands): March 31, 2021 December 31, 2020 Accounts receivable - Utility Members $ 88,369 $ 96,637 Other accounts receivable - trade: Non-member electric sales 3,239 5,231 Other 9,855 9,785 Total other accounts receivable - trade 13,094 15,016 Other accounts receivable - nontrade 3,192 5,554 Total other accounts receivable $ 16,286 $ 20,570 Contract liabilities (unearned revenue) $ 6,301 $ 6,025

OTHER DEFERRED CHARGES (Tables)

OTHER DEFERRED CHARGES (Tables)	3 Months Ended
	Mar. 31, 2021
Deferred Costs [Abstract]
Schedule of Other Deferred Charges	The following other deferred charges are reflected on our consolidated statements of financial position (dollars in thousands): March 31, 2021 December 31, 2020 Preliminary surveys and investigations $ 12,142 $ 12,886 Advances to operating agents of jointly owned facilities 11,425 2,071 Operating lease right-of-use assets 7,999 7,985 Other 15,072 10,704 Total other deferred charges $ 46,638 $ 33,646

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	3 Months Ended
	Mar. 31, 2021
Debt Disclosure [Abstract]
Schedule of long-term debt	Long-term debt consists of the following (dollars in thousands): March 31, 2021 December 31, 2020 Total debt $ 3,262,606 $ 3,308,715 Less debt issuance costs (24,963) (25,590) Less debt discounts (9,595) (9,659) Plus debt premiums 13,967 14,302 Total debt adjusted for debt issuance costs, discounts and premiums 3,242,015 3,287,768 Less current maturities (94,592) (87,587) Long-term debt $ 3,147,423 $ 3,200,181

ASSET RETIREMENT AND ENVIRONM_2

ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS (Tables)	3 Months Ended
	Mar. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	Aggregate carrying amounts of asset retirement obligations and environmental reclamation obligations are as follows (dollars in thousands): Three Months Ended 2021 Obligations at beginning of period $ 138,089 Liabilities incurred — Liabilities settled (107) Accretion expense 803 Change in cash flow estimate — Total obligations at end of period $ 138,785 Less current obligations at end of period (11,080) Long-term obligations at end of period $ 127,705

OTHER DEFERRED CREDITS AND OT_2

OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Tables)	3 Months Ended
	Mar. 31, 2021
Deferred Credits and Other Liabilities [Abstract]
Schedule of other deferred credits and other liabilities	The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands): March 31, 2021 December 31, 2020 Transmission easements $ 19,621 $ 19,983 Operating lease liabilities - noncurrent 1,761 1,590 Contract liabilities (unearned revenue) - noncurrent 3,611 3,702 Customer deposits 8,935 7,712 Financial liabilities - reclamation 11,924 12,081 Deposits associated with generator interconnection requests 17,130 — Other 9,419 9,532 Total other deferred credits and other liabilities $ 72,401 $ 54,600

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	3 Months Ended
	Mar. 31, 2021
Retirement Benefits [Abstract]
Schedule of employee benefit plan obligations	The postretirement medical benefit and postemployment medical benefit obligations are determined annually (during the fourth quarter) by an independent actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands): Three Months Ended 2021 Postretirement medical benefit obligation at beginning of period $ 9,985 Service cost 150 Interest cost 65 Benefit payments (net of contributions by participants) (148) Postretirement medical benefit obligation at end of period $ 10,052 Postemployment medical benefit obligation at end of period 419 Total postretirement and postemployment medical obligations at end of period $ 10,471 The NRECA Executive Benefit Restoration Plan obligations are determined annually (during the first quarter of the subsequent year) by an NRECA actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands): Three Months Ended 2021 Executive benefit restoration obligation at beginning of period $ 7,379 Service cost 137 Interest cost 53 Actuarial loss 1,121 Executive benefit restoration at end of period $ 8,690 Fair value of plan assets at beginning of period $ 6,955 Employer contributions 403 Actual return on plan assets $ (41) Fair value of plan assets at end of period $ 7,317 Net liability recognized $ 1,373
Schedule of the net unrecognized actuarial gains and losses related to employee benefit plan obligations	The net unrecognized actuarial gains and losses related to the postretirement medical benefit obligations are included in accumulated other comprehensive income as follows (dollars in thousands): Three Months Ended 2021 Accumulated other comprehensive loss at beginning of period $ (841) Amortization of prior service credit into other income (20) Accumulated other comprehensive loss at end of period $ (861) The net unrecognized actuarial gains and losses related to the executive benefit restoration obligations are included in accumulated other comprehensive income as follows (dollars in thousands): Three Months Ended 2021 Accumulated other comprehensive loss at beginning of period $ (4,873) Amortization of prior service cost into other income 220 Amortization of actuarial loss 171 Curtailment and settlement 141 Unrecognized actuarial loss (1,121) Accumulated other comprehensive loss at end of period $ (5,462)

REVENUE (Tables)

REVENUE (Tables)	3 Months Ended
	Mar. 31, 2021
Revenue from Contract with Customer [Abstract]
Schedule of revenue from contracts with non-member customers and other operating revenue	The following revenue is reflected on our consolidated statements of operations as follows (dollars in thousands): Three Months Ended March 31, 2021 2020 Non-member electric sales: Long-term contracts $ 8,706 $ 12,144 Short-term contracts 8,634 3,669 Recognition of deferred revenue 20,834 — Other 15,000 10,890 Total non-member electric sales and other operating revenue $ 53,174 $ 26,703

LEASES (Tables)

LEASES (Tables)	3 Months Ended
	Mar. 31, 2021
Leases [Abstract]
Schedule of lease components	Our consolidated statements of financial position include the following lease components (dollars in thousands): March 31, 2021 December 31, 2020 Operating leases Operating lease right-of-use assets $ 9,331 $ 9,223 Less: Accumulated amortization (1,332) (1,238) Net operating lease right-of-use assets $ 7,999 $ 7,985 Operating lease liabilities - current $ (499) $ (526) Operating lease liabilities - noncurrent (1,761) (1,590) Total operating lease liabilities $ (2,260) $ (2,116) Operating leases Weighted average remaining lease term (years) 7.7 7.6 Weighted average discount rate 3.85 % 3.84 %
Schedule of expected minimum lease commitments under operating leases	Future expected minimum lease commitments under operating leases are as follows (dollars in thousands): Year 1 $ 527 Year 2 365 Year 3 336 Year 4 286 Year 5 100 Thereafter 690 Total lease payments $ 2,304 Less imputed interest (44) Total $ 2,260

FAIR VALUE (Tables)

FAIR VALUE (Tables)	3 Months Ended
	Mar. 31, 2021
Fair Value Disclosures [Abstract]
Schedule of carrying amounts and fair values of assets and liabilities	The cost and fair values of our marketable securities are as follows (dollars in thousands): March 31, 2021 December 31, 2020 Cost Estimated Cost Estimated EBR Trust investments $ 7,384 $ 7,316 $ 6,955 $ 6,955 March 31, 2021 December 31, 2020 Cost Estimated Cost Estimated Marketable securities $ 493 $ 503 $ 491 $ 478 March 31, 2021 December 31, 2020 Principal Estimated Principal Estimated Total debt $ 3,262,606 $ 3,748,334 $ 3,308,715 $ 3,908,497

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	3 Months Ended
	Mar. 31, 2021
Variable Interest Entity or Potential VIE, Information Unavailability, Disclosures [Abstract]
Schedule of consolidated variable interest entities	Assets and liabilities of the Springerville Partnership that are included in our consolidated statements of financial position are as follows (dollars in thousands): March 31, 2021 December 31, 2020 Net electric plant $ 753,739 $ 758,273 Noncontrolling interest 113,807 114,852 Long-term debt 301,066 342,355 Accrued interest 3,488 9,942 Our consolidated statements of operations include the following Springerville Partnership expenses for the three months ended March 31, 2021 and 2020 (dollars in thousands): March 31, 2021 2020 Depreciation, amortization and depletion $ 4,534 $ 4,534 Interest 5,185 5,861

PRESENTATION OF FINANCIAL INF_3

PRESENTATION OF FINANCIAL INFORMATION (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2021USD ($)memberSystemfacility
Jointly owned facilities
Number of classes of members | memberSystem	3
Number of jointly owned facilities | facility	2
Electric plant in service	$ 894,728
Accumulated depreciation	571,176
Construction work in progress	$ 4,469
Yampa
Jointly owned facilities
Tri-State share (as a percent)	24.00%
Electric plant in service	$ 395,810
Accumulated depreciation	253,638
Construction work in progress	$ 418
MBPP
Jointly owned facilities
Tri-State share (as a percent)	27.13%
Electric plant in service	$ 498,918
Accumulated depreciation	317,538
Construction work in progress	$ 4,051
Class A Members
Jointly owned facilities
Number of members | memberSystem	42
Class B Members
Jointly owned facilities
Number of members | memberSystem	0
Non-Utility Members
Jointly owned facilities
Number of members | memberSystem	3

ACCOUNTING FOR RATE REGULATIO_2

ACCOUNTING FOR RATE REGULATION (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended
	Oct. 31, 2017	Mar. 31, 2021	Dec. 31, 2020
Regulatory assets and liabilities
Regulatory assets		$ 699,480	$ 710,268
Regulatory liabilities		203,981	224,953
Net regulatory asset		495,499	485,315
Deferred non-member electric sales
Regulatory assets and liabilities
Regulatory liabilities		42,883	63,717
Deferred revenue from membership withdrawal
Regulatory assets and liabilities
Regulatory liabilities		157,943	157,943
Interest rate swaps, realized gain
Regulatory assets and liabilities
Regulatory liabilities		$ 3,155	3,293
Proceeds from settlement of interest rate swaps	$ 4,600
First Mortgage Obligations, Series 2017A , Tranche 1, 3.34%, due through 2029
Regulatory assets and liabilities
Term of issuance		12 years
Deferred income tax expense
Regulatory assets and liabilities
Regulatory assets		$ 19,641	19,641
Deferred prepaid lease expense | Springerville Unit 3 Lease
Regulatory assets and liabilities
Regulatory assets		80,851	81,424
Annual amortization expense		$ 2,300
Amortization period		47 years
Goodwill | TCP
Regulatory assets and liabilities
Regulatory assets		$ 45,584	46,296
Annual amortization expense		$ 2,800
Amortization period		25 years
Goodwill | Colowyo Coal
Regulatory assets and liabilities
Regulatory assets		$ 35,903	36,161
Annual amortization expense		$ 1,000
Amortization period		44 years
Deferred debt prepayment transaction costs
Regulatory assets and liabilities
Regulatory assets		$ 130,145	132,302
Annual amortization expense		$ 8,600
Amortization period		21 years 4 months 24 days
Deferred impairment loss | Holcomb Expansion
Regulatory assets and liabilities
Annual amortization expense		$ 11,300
Deferred impairment loss | Unrecovered Plants
Regulatory assets and liabilities
Regulatory assets		$ 299,705	305,625
Deferred impairment loss | Nucla Generating Station
Regulatory assets and liabilities
Amortization period		3 years 3 months 18 days
Deferred impairment loss | Holcomb Expansion
Regulatory assets and liabilities
Regulatory assets		$ 87,651	$ 88,819
Annual amortization expense		$ 4,700
Amortization period		20 years

INVESTMENTS IN OTHER ASSOCIAT_3

INVESTMENTS IN OTHER ASSOCIATIONS (Details) - USD ($)	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Investment in other associations
Investment in other associations	$ 164,248,000		$ 162,975,000
Impairment during the period	0	$ 0
Basin Electric Power Cooperative
Investment in other associations
Investment in other associations	118,295,000		118,295,000
National Rural Utilities Cooperative Finance Corporation - patronage capital
Investment in other associations
Investment in other associations	11,933,000		11,933,000
National Rural Utilities Cooperative Finance Corporation - capital term certificates
Investment in other associations
Investment in other associations	15,149,000		15,221,000
CoBank, ACB
Investment in other associations
Investment in other associations	12,707,000		11,141,000
Western Fuels Association, Inc.
Investment in other associations
Investment in other associations	2,200,000		2,283,000
Other
Investment in other associations
Investment in other associations	$ 3,964,000		$ 4,102,000

CASH, CASH EQUIVALENTS AND RE_3

CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020	Mar. 31, 2020	Dec. 31, 2019
Cash, cash equivalents, restricted cash and investments
Cash and cash equivalents	$ 109,483	$ 127,187
Restricted cash and investments - current	274	205
Restricted cash and investments - noncurrent	4,546	4,682
Cash, cash equivalents and restricted cash and investments	$ 114,303	$ 132,074	$ 185,837	$ 113,768

CONTRACT ASSETS AND CONTRACT _3

CONTRACT ASSETS AND CONTRACT LIABILITIES (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
Accounts receivable
Accounts receivable—Utility Members	$ 88,369	$ 96,637
Other accounts receivable	16,286	20,570
Contract liabilities
Contract liabilities (unearned revenue)	6,301	6,025
Other accounts receivable - trade
Accounts receivable
Other accounts receivable	13,094	15,016
Other accounts receivable - trade | Non-member electric sales
Accounts receivable
Other accounts receivable	3,239	5,231
Other accounts receivable - trade | Other
Accounts receivable
Other accounts receivable	9,855	9,785
Other accounts receivable, non-trade
Accounts receivable
Other accounts receivable	3,192	$ 5,554
Other operating revenue
Contract liabilities
Contract liabilities recognized	$ 100

OTHER DEFERRED CHARGES (Details

OTHER DEFERRED CHARGES (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Deferred Costs [Abstract]
Preliminary surveys and investigations	$ 12,142	$ 12,886
Advances to operating agents of jointly owned facilities	11,425	2,071
Operating lease right-of-use assets	7,999	7,985
Other	15,072	10,704
Total other deferred charges	$ 46,638	$ 33,646

LONG-TERM DEBT - Other Informat

LONG-TERM DEBT - Other Information (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2021USD ($)$ / shares	Dec. 31, 2020USD ($)
Debt
Long-term debt	$ 3,147,423	$ 3,200,181
Number of unsecured debt instruments | $ / shares	1
Unsecured notes	$ 17,700
Minimum
Debt
Equity to capitalization ratio (ECR) requirement	18.00%
Debt service ratio (DSR) requirement	1.10
Springerville certificates, Series B, 7.14%, due through 2033
Debt
Debt service ratio (DSR) requirement	1.02
2018 Revolving Credit Agreement
Debt
Maximum borrowing capacity	$ 650,000
Available borrowing capacity	650,000
2018 Revolving Credit Agreement | Commercial Paper
Debt
Available borrowing capacity	500,000
Swingline
Debt
Maximum borrowing capacity	100,000
Letter of Credit
Debt
Maximum borrowing capacity	75,000
Commercial Paper
Debt
Maximum borrowing capacity	$ 500,000

LONG-TERM DEBT - Components (De

LONG-TERM DEBT - Components (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Long-term debt, components
Total debt	$ 3,262,606	$ 3,308,715
Less debt issuance costs	(24,963)	(25,590)
Less debt discounts	(9,595)	(9,659)
Plus debt premiums	13,967	14,302
Total debt adjusted for debt issuance costs, discounts and premiums	3,242,015	3,287,768
Less current maturities	(94,592)	(87,587)
Long-term debt	$ 3,147,423	$ 3,200,181

SHORT-TERM BORROWINGS (Details)

SHORT-TERM BORROWINGS (Details) - USD ($)	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
2018 Revolving Credit Agreement
Short-term borrowings
Available borrowing capacity	$ 650,000,000
Commercial Paper
Short-term borrowings
Short-term borrowings	0	$ 0
Commercial Paper | 2018 Revolving Credit Agreement
Short-term borrowings
Available borrowing capacity	500,000,000
Maximum | Commercial Paper
Short-term borrowings
Maximum amount per commercial paper sublimit	$ 500,000,000

ASSET RETIREMENT AND ENVIRONM_3

ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2021USD ($)	Dec. 31, 2019item	Dec. 31, 2020USD ($)
Aggregate carrying amounts of asset retirement obligations
Obligations at beginning of period	$ 138,089
Liabilities incurred	0
Liabilities settled	(107)
Accretion expense	803
Change in cash flow estimate	0
Total obligations at end of period	138,785
Less current obligations at end of period	(11,080)		$ (11,044)
Long-term obligations at end of period	$ 127,705
Colowyo Mine
Asset Retirement And Environmental Reclamation Obligations
Number of mine pits in final reclamation | item		1

OTHER DEFERRED CREDITS AND OT_3

OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
Deferred credits and other liabilities
Transmission easements	$ 19,621	$ 19,983
Operating lease liabilities - noncurrent	1,761	1,590
Contract liabilities (unearned revenue) - noncurrent	3,611	3,702
Customer deposits	8,935	7,712
Financial liabilities - reclamation	11,924	12,081
Deposits associated with generator interconnection requests	17,130	0
Other	9,419	9,532
Total other deferred credits and other liabilities	72,401	54,600
Transmission Right of Way Easements
Deferred credits and other liabilities
Total due for easement right of way	29,400
Transmission Right of Way Easements | Other Deferred Credits and Other Liabilities
Deferred credits and other liabilities
Transmission easements	$ 19,600	$ 20,000

EMPLOYEE BENEFIT PLANS - Postre

EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other Than Pensions, Obligations (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2021USD ($)plan
Postretirement Medical Benefit Plans
Postretirement medical benefit and postemployment medical benefit obligations
Postretirement medical benefit obligation at beginning of period	$ 9,985
Service cost	150
Interest cost	65
Benefit payments (net of contributions by participants)	(148)
Total postretirement and postemployment medical obligations at end of period	$ 10,052
Threshold percentage, unrecognized amount of actuarial gains and losses as a percentage of projected benefit obligation	10.00%
Postemployment Medical Benefit Plans
Postretirement medical benefit and postemployment medical benefit obligations
Total postretirement and postemployment medical obligations at end of period	$ 419
Medical Plans
Postretirement medical benefit and postemployment medical benefit obligations
Total postretirement and postemployment medical obligations at end of period	$ 10,471
Non-bargaining unit employees | Postretirement Medical Benefit Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	2
Non-bargaining unit employees | Postretirement Medical Benefit Plans | Minimum
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Qualifying age	55 years
Non-bargaining unit employees | Postemployment Medical Benefit Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	3
Non-bargaining unit employees | Medical Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	3
Non-bargaining unit employees | Medical Plans | Maximum
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Qualifying age	65 years

EMPLOYEE BENEFIT PLANS - Post_2

EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other Than Pensions, Actuarial Gains and Losses (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Net unrecognized actuarial gains and losses
Amortization of prior service cost	$ 512	$ 933
Postretirement Medical Benefit Plans
Net unrecognized actuarial gains and losses
Accumulated other comprehensive loss at beginning of period	(841)
Amortization of prior service cost	(20)
Accumulated other comprehensive loss at end of period	$ (861)

EMPLOYEE BENEFIT PLANS - NRECA

EMPLOYEE BENEFIT PLANS - NRECA Executive Benefit Restoration Plan, Obligations (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2021USD ($)
Defined benefit plans, Plan Assets
Fair value of plan assets at beginning of period	$ 6,955
Employer contributions	403
Fair value of plan assets at end of period	7,317
Net liability recognized	1,373
NRECA Executive Benefit Restoration Plan
Defined Benefit Plans
Postretirement medical benefit obligation at beginning of period	7,379
Service cost	137
Interest cost	53
Actuarial loss	1,121
Total postretirement and postemployment medical obligations at end of period	$ 8,690
Defined benefit plans, Plan Assets
Threshold percentage, unrecognized amount of actuarial gains and losses as a percentage of projected benefit obligation	10.00%
Executive Benefit Restoration Plan
Defined Benefit Plans
Actuarial loss	$ 41

EMPLOYEE BENEFIT PLANS - NREC_2

EMPLOYEE BENEFIT PLANS - NRECA Executive Benefit Restoration Plan, Actuarial Gains and Losses (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Net unrecognized actuarial gains and losses
Amortization of prior service cost	$ 512	$ 933
Amortization of actuarial loss	171
Curtailment and settlement	141
NRECA Executive Benefit Restoration Plan
Net unrecognized actuarial gains and losses
Accumulated other comprehensive loss at beginning of period	(4,873)
Amortization of prior service cost	220
Unrecognized actuarial loss	(1,121)
Accumulated other comprehensive loss at end of period	$ (5,462)

REVENUE - Member Electric Sales

REVENUE - Member Electric Sales (Details)	3 Months Ended
	Mar. 31, 2021utilityMemberbillingCompanydemandRate
Disaggregation of Revenue [Line Items]
Number of billing components of Class A rate schedule for electric power sales to Members | billingCompany	3
Number of demand rates | demandRate	2
Member Contracts Extending Through 2050
Disaggregation of Revenue [Line Items]
Number of contracts | utilityMember	42

REVENUE - Revenue Reflected in

REVENUE - Revenue Reflected in Statement of Operations (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2021USD ($)non-utilityMember	Mar. 31, 2020USD ($)
Disaggregation of revenue
Recognition of deferred revenue	$ 20,834	$ 0
Other	15,000	10,890
Total non-member electric sales and other operating revenue	$ 325,972	319,466
Number of non-utility members from whom other operating revenue is received | non-utilityMember	2
Non-member electric sales
Disaggregation of revenue
Revenue from contract with customer	$ 38,174	15,813
Recognition of deferred revenue	20,834	0
Non-member electric sales | Long-term contracts
Disaggregation of revenue
Revenue from contract with customer	8,706	12,144
Non-member electric sales | Short-term contracts
Disaggregation of revenue
Revenue from contract with customer	8,634	3,669
Other
Disaggregation of revenue
Other	15,000	10,890
Total non-member electric sales and other operating revenue
Disaggregation of revenue
Total non-member electric sales and other operating revenue	$ 53,174	$ 26,703

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Income Tax Disclosure [Abstract]
Income tax expense (benefit)	$ 109	$ (209)

LEASES - Leasing Arrangements a

LEASES - Leasing Arrangements as Lessee (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021USD ($)lease	Mar. 31, 2020USD ($)
Leases [Abstract]
Operating lease expense | $	$ 1	$ 0.9
Number of financing leases | lease	0

LEASES - Lease Components (Deta

LEASES - Lease Components (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating lease right-of-use assets	$ 9,331	$ 9,223
Less: Accumulated amortization	(1,332)	(1,238)
Net operating lease right-of-use assets	7,999	7,985
Operating lease liabilities - current	(499)	(526)
Operating lease liabilities - noncurrent	(1,761)	(1,590)
Total operating lease liabilities	$ (2,260)	$ (2,116)
Weighted average remaining lease term (years)	7 years 8 months 12 days	7 years 7 months 6 days
Weighted average discount rate	3.85%	3.84%
Operating lease right-of-use asset, Statement of Financial Position line item	Other	Other
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:LiabilitiesCurrent	us-gaap:LiabilitiesCurrent
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:DeferredLongTermLiabilityCharges	us-gaap:DeferredLongTermLiabilityCharges

LEASES - Future Minimum Lease C

LEASES - Future Minimum Lease Commitments (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Future expected minimum lease commitments under operating leases
Year 1	$ 527
Year 2	365
Year 3	336
Year 4	286
Year 5	100
Thereafter	690
Total lease payments	2,304
Less imputed interest	(44)
Total	$ 2,260	$ 2,116

LEASES - Leasing Arrangements_2

LEASES - Leasing Arrangements as Lessor (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Leases [Abstract]
Lease revenue	$ 1.8	$ 1.6

FAIR VALUE (Details)

FAIR VALUE (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Fair value:
Cash and cash equivalents	$ 88,200	$ 94,600
Cost
Fair value:
Marketable securities	493	491
Long-term debt	3,262,606	3,308,715
Cost | EBT Trust Investments
Fair value:
Marketable securities	7,384	6,955
Estimated Fair Value
Fair value:
Marketable securities	503	478
Long-term debt	3,748,334	3,908,497
Estimated Fair Value | EBT Trust Investments
Fair value:
Marketable securities	$ 7,316	$ 6,955

VARIABLE INTEREST ENTITIES - Co

VARIABLE INTEREST ENTITIES - Consolidated Entities (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Consolidated Variable Interest Entities
Net electric plant	$ 3,350,260		$ 3,352,706
Noncontrolling interest	113,807		114,851
Long-term debt	3,147,423		3,200,181
Accrued interest	45,321		27,520
Interest	$ 35,141	$ 36,906
Springerville Partnership
Consolidated Variable Interest Entities
Equity interest (as a percent)	51.00%
General partner interest (as a percent)	1.00%
Springerville Partnership | Springerville Unit 3 Lease
Consolidated Variable Interest Entities
Percentage of financial and other support provided	100.00%
Springerville Partnership | Springerville Unit 3 Holding LLC
Consolidated Variable Interest Entities
Ownership interest held by parent (as a percent)	100.00%
Springerville Partnership | Reportable Legal Entities
Consolidated Variable Interest Entities
Net electric plant	$ 753,739		758,273
Noncontrolling interest	113,807		114,852
Long-term debt	301,066		342,355
Accrued interest	3,488		$ 9,942
Depreciation, amortization and depletion	4,534	4,534
Interest	$ 5,185	$ 5,861
Other Limited Partners | Springerville Partnership
Consolidated Variable Interest Entities
Ownership interest held by noncontrolling interest (as a percent)	49.00%

LEGAL - Legal (Details)

LEGAL - Legal (Details) - USD ($) $ in Millions	Apr. 30, 2021	Mar. 31, 2021	Apr. 30, 2022
Subsequent Event
Other legal
Rate reduction due to settlement	2.00%		4.00%
Revenue from Contract with Customer, Excluding Assessed Tax, Amount Held Due To Reduction In Utility Member Rate	$ 1.7
Members | Maximum
Other legal
Annual allowance for self-supply of a member's electric power requirements		5.00%